Devices and methods for generating radially propogating ultrasonic waves and their use

ABSTRACT

An acoustic waveguide includes a body defining a resonance chamber. The body has a tubular section defining a cylindrical central portion of the chamber along a longitudinal axis. First and second end sections extend from opposite ends of the tubular section. Each end section includes an end wall tapering away from the tubular section and towards the longitudinal axis, thus defining a conoidal end portion of the chamber.

FIELD

The present invention relates generally to sonic devices, and particularly to ultrasonic devices and related methods and their uses.

BACKGROUND

Sonic devices such as ultrasonic devices have applications in various fields and industries. For example, ultrasonic devices have been used in oil extraction processes. A sonotrode may be placed in a production well penetrating an oil reservoir to generate ultrasonic waves for assisting oil production.

Oil recovery efficiency from subterranean reservoirs containing viscous hydrocarbons may be improved or enhanced with the injection of sound waves or acoustic energy, such as to heat and reduce the viscosity of oil, increase the permeability of the reservoir formation, and generally induce migration of oil in the formation into the well bore. Enhanced oil recovery (EOR) techniques also include injection of heat energy, such as using steam or heated fluid, or a chemical agent, such as solvent, surfactant, diluting liquid, detergent, wetting agent, emulsifier, foaming agent, or dispersant, into the reservoir. Different techniques may be combined to achieve better results.

An example of an acoustic device used for increasing oil production through vertical wells is disclosed in U.S. Pat. No. 7,063,144 to Abramov et al., entitled “Acoustic Well Recovery Method and Device” and issued Jun. 20, 2006.

EOR through horizontal wells presents unique challenges, as compared to recovery through vertical wells, but also presents opportunities for innovative techniques to achieve improved results or efficiency. Improvement to recovery techniques through vertical wells is also desired.

SUMMARY

It has been surprisingly discovered that an acoustic waveguide having a resonance cavity with conoidal end portions can provide more efficient radial dispersion of acoustic energy and thus improved performance, such as when used in fluid production from horizontal wells, or from vertical or directional wells.

Thus, in one aspect, the present disclosure relates to an acoustic waveguide comprising a body defining a resonance chamber, the body comprising a tubular section defining a cylindrical central portion of the chamber along a longitudinal axis; and first and second end sections extending from opposite ends of the tubular section, each one of the end sections comprising an end wall tapering away from the tubular section and towards the longitudinal axis thus defining a conoidal end portion of the chamber. The end wall and the longitudinal axis may be at an angle of about 45 to about 70 degrees, such as about 50 to about 55 degrees. The resonance chamber may contain a rarefied gas. The resonance chamber may be sized and shaped to exhibit a resonant frequency in the range of 10 to 50 kHz. The waveguide may be configured and sized to optimize radial dispersion of sonic energy through the waveguide.

In another aspect, there is provided a sonic device comprising a waveguide disclosed herein, and an acoustic transducer coupled to at least one of the end sections of the waveguide. The transducer may be a magnetostrictive or piezoelectric transducer. The sonic device may further comprise a housing, wherein the transducer is mounted in the housing and is immersed in a cooling fluid. The sonic device may further comprise a pressure compensator in the housing. The transducer may have a working frequency, and the waveguide may be configured such that a resonant frequency of the sonic device matches the working frequency of the transducer. The resonant frequency may be a resonant frequency of longitudinal oscillation. The resonant frequency of the sonic device may differ from the working frequency of the transducer by less than 10% of the working frequency. The transducer may comprise a magnetostrictive transducer. The magnetostrictive transducer may have first and second elongated openings, aligned and spaced apart in a longitudinal direction, and wherein a coil passes through each one of the first and second openings. Each one of the end sections of the waveguide may be coupled to an acoustic transducer.

A further aspect relates to a method comprising generating a radially propagating acoustic wave with a sonic device as disclosed herein, which is positioned in a well penetrating a hydrocarbon reservoir. The method may further comprise injecting a chemical agent into the well. The sonic device may be connected to an injector for injecting the chemical agent, and the sonic device and injector may be moved to and fro in the well in synchronization. The sonic device and injector may be connected to a cable, such as a cable hose. The cable hose may comprise a fluid conduit for supplying the chemical agent to the injector and a conducting wire for transmitting power to the sonic device. The cable hose may further comprise a signal wire for transmitting a signal therethrough. The well may be a horizontal well, a vertical well, or a directional well.

In another aspect, there is provided a downhole tool assembly comprising a sonic device disclosed herein; an injector for injecting a chemical agent into a perforated wellbore portion of a well penetrating a hydrocarbon reservoir; and a movable cable hose connected to the injector and the sonic device for moving the injector and the sonic device to and fro in synchronization, the cable hose comprising a conducting wire for supplying power to the sonic device and having a conduit for supplying the chemical agent to the injector. The cable hose may further comprise a signal wire for transmitting a signal therethrough.

Other aspects, features, and embodiments of the present disclosure will become apparent to those of ordinary skill in the art upon review of the following description of specific embodiments in conjunction with the accompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

In the figures, which illustrate, by way of example only, embodiments of the present disclosure:

FIG. 1A is a schematic cross-sectional view of an acoustic waveguide;

FIG. 1B is an axial cross-sectional view of the acoustic waveguide of FIG. 1A, taken along line 1B-1B;

FIG. 2 is a schematic cross-sectional view of a sonic device including the acoustic waveguide of FIG. 1A coupled to acoustic transducers;

FIG. 3A is a cross-sectional view of the sonic device with additional components;

FIGS. 3B and 3C are axial cross-section view of the sonic device of FIG. 3A, taken along lines 3A-3A and 3B-3B respectively;

FIG. 4 is a schematic cross-sectional view of a base body for a magnetostrictive transducer;

FIG. 5A is a schematic cross-sectional elevation view of a tool assembly in a horizontal well penetrating a reservoir formation;

FIG. 5B is a cross-sectional view of the cable hose in the tool assembly of FIG. 5A;

FIG. 5C is a schematic cross-sectional view of an end section of the sonotrode in the tool assembly of FIG. 5A;

FIG. 6 is a schematic cross-sectional elevation view of another tool assembly in a vertical well penetrating a reservoir formation; and

FIG. 7 is a graph showing calculation results of displacement distribution in a sample sonic device.

DETAILED DESCRIPTION

An embodiment of the present disclosure relates to an acoustic waveguide 100 as illustrated in FIGS. 1A and 1B.

Waveguide 100 has a generally cylindrical body 101, which defines a resonance chamber 102. Body 101 includes a tubular section 104 and two end sections 106 extending from opposite ends of tubular section 104. Tubular section 104 defines a cylindrical central portion of chamber 102. Cylindrical body 101, tubular section 104, and the cylindrical central portion of chamber 102 extend along a central axis 108. Each end section 106 has a tapered wall 110, which tapers away from tubular section 104 and towards central axis 108, thus defining a conoidal end portion of chamber 102.

Chamber 102 may be filled with a rarefied gas. The gas may be air at a reduced pressure. As can be appreciated, sound wave propagation requires a medium, and cannot occur in complete vacuum. Sound wave propagation in a dense medium can result in significant energy loss. Therefore, a resonance chamber filled with a rarefied gas, or partially evacuated, has an increased efficiency, as compared to a resonance chamber filled with atmospheric air, since potential loss of acoustic energy in the chamber are reduced or minimized. Potential energy loss may be due to transfer of acoustic energy into the chamber and conversion of acoustic energy to another form of energy such as heat or vibration inside the chamber.

The angle (θ) between central axis 108 and each end wall 110 may vary from about 45° to about 70°. As will be further discussed below, in some embodiments, θ may be about 50° to about 55°. The angle θ may be selected to optimize operation performance as will be further discussed below. As can be appreciated, a change in the angle θ can result in a change in oscillation amplitude in different directions and in own oscillation frequencies. See below for test results of the effects of changing θ. For example, in some configurations, a maximum amplitude may be obtained when θ is between 50° to 55°.

The dimensions of body 101, tubular section 104 and end sections 106 are selected to provide a selected or desired resonance frequency (f_(r)). For example, when waveguide 100 is to be coupled to an acoustic transducer with a working frequency f_(w) (see below), the resonance frequency f_(r) may be selected to match the working frequency f_(w). For the purpose of this disclosure, f_(r) is considered to match f_(w) if f_(r)=f_(w) or if (f_(r)−f_(w))/f_(w)<0.1. The resonance frequency normally refers to a longitudinal oscillation frequency (that is, the resonant vibration frequency in the axial direction). For example, tubular section 104 may have a length of about 258 mm and an outer diameter of about 44 mm. Different lengths and diameters may also be suitable or selected in various embodiments and applications. The thickness of tubular section 104 of body 101 may be about 6 mm. This thickness may be selected so that it is sufficiently thin to efficiently transmit acoustic energy with limited or minimized energy loss, and it is sufficiently thick to have the required physical strength for normal operation.

Body 101 may be formed of any suitable material for forming acoustic waveguides, particularly waveguides for providing ultrasonic resonance. For example, body 101 may be formed of a suitable metal or alloy. In some embodiments, titan may be used to form body 101. In some embodiments, stainless steel may be used to form body 101.

Body 101 may optionally include channels or conduits (not shown in FIG. 1A, but see FIG. 2 for an example) for various purposes, such as for inserting an energy source or another component into body 101.

Chamber 102 may be filled with a rarefied gas. The rarefied gas may include air at a reduced pressure. The pressure may be close to zero to provide optimal efficiency. In some cases, the pressure may be reduced to as low as is practically possible.

In use, waveguide 100 may be coupled to an acoustic transducer that generates mainly longitudinal sound vibrations to efficiently produce radially propagating sound waves.

An example of such use is schematically illustrated in FIG. 2. As depicted in FIG. 2, a sonic device 200, which may be referred to as a sonotrode, includes waveguide 100 and two acoustic transducers 202 coupled to opposite axial ends of waveguide 100 respectively.

Each transducer 202 may be constructed according to a suitable known acoustic transducer technique. Example conventional techniques for constructing suitable acoustic transducers include those disclosed in, e.g., O. V. Abramov, “High-Intensity Ultrasonics: Theory and Industrial Applications,” CRC Press, 1999.

In some embodiments, transducers 202 may include an electric powered magnetostrictive transducer, and may be made of permendur. In some embodiments, other suitable materials with magnetostrictive or piezoelectric properties may be used. As is known to those skilled in the art, an electrical coil may be wound around a transducer 202 to induce an alternating magnetic field in the transducer body when an alternating electrical current is applied through the coil. The varying magnetic field causes the transducer body to expand or contract, resulting in a corresponding oscillating displacement of an adjacent object abutting the transducer, such as waveguide 100 shown in FIG. 2. When the oscillation frequency is suitably selected, ultrasonic waves are generated and transmitted outward into the surroundings. Sonotrodes 200 may be configured to maximize radial dispersion of ultrasonic waves.

In an embodiment, the dimensions of waveguide 100 and transducers 202 may be as listed in Table I.

TABLE I Dimensions of Sample Sonic Device illustrated in FIG. 2 Length (mm) Diameter (mm) Cone Angle θ Waveguide Body 405 44 Cylindrical Portion 258 32 End Portion 73.5 44 55 Transducer Body 134

In this example, transducer 202 has a working (operating) frequency of 18.49 kHz and the entire device (a waveguide and two transducers) has a resonant frequency of 18.55 kHz.

As will be appreciated and understood by those skilled in the art, to implement device 200 in a practical application, additional features and components will be required, for example, to provide power and control of the device, and to interconnect different components in the device and connect the device to other tools or equipment used in a particular application. Additional components may also be necessary or optional to provide other functionalities or improved performance, some of which will be illustrated below.

In particular, for simplification, the windings for providing a varying magnetic field are not shown in some figures as they are not needed to show the modifications under discussion, but it should be understood that appropriate windings will be required in some practical implementations.

An example sonic device 300 is illustrated in FIG. 3. In this embodiment, the acoustic transducer may include a transducer body 204 enclosed in a housing 302 filled with a cooling liquid 304, such as oil.

An electrical conducting wire may be wound about each transducer body 204 and connected to a power source for generating a varying magnetic field in the transducer 300. The transducer body 204 may have an opening 206, as depicted in FIG. 3A (also see FIG. 2), to allow the conducting wire to be wound through opening 206 around each of the top section and the bottom section of body 204.

Opening 206 may be selected so that necessary windings can be provided therethrough. The number of coil windings can affect the efficiency of the device. The winding may be selected to match the impedance, and will depend on the material characteristics of the material used to form the transducer. It may be desirable to operate in or near the saturation zone of the material. The width of opening 206 is selected depending on the diameter of the winding wire or cable. That is, the winding wire or cable will need to be able to fit within the opening. A winding cable may be chosen based on its characteristics, taking into account of the desired current that will pass through the cable during operation.

As depicted in FIG. 3A, a winding wire (or cable) 306 may be used to form windings on both transducers 302 and may pass through waveguide 100. Winding wire 306 is connected to a power source or signal source (not shown) for supplying the power or signal required for operation. To allow winding wire 306 to pass through waveguide 100, a channel 308 may be provided. Channel 308 may be filled with a fluid 312, which can be the same as fluid 304.

Device 300 may have a working frequency range from about 10-50 kHz, such as about 20 kHz.

In alternative embodiments, the transducer body may have two winding openings as illustrated in FIG. 4. The transducer 400 depicted in FIG. 4 has a transducer body 402 with two elongated openings 404 and 406. Openings 404 and 406 are aligned and spaced apart, such as by a distance of about one to two times of the distance between each opening to the side edge of the device. Each opening 404 and 406 has a generally rectangular profile, with length and height selected to accommodate the winding wires to be passed therethrough, as discussed above.

Sonic device 200 or 300 may be used in an oil or gas extraction process, such as illustrated in FIG. 5A.

As depicted in FIG. 5A, a horizontal well 520 penetrates a reservoir 530 containing hydrocarbons, which may be present in the form of oil or gas. Horizontal well 520 is completed with a cement casing 522 around the perimeter of the wellbore, as can be understood by those skilled in the art. Casing 522 at a horizontal section of well 520 has perforations extending through cement casing 522 to provide fluid pathways and fluid communication between well 520 and reservoir 530. As is typical, a string of tubing 524 extends into well 520 from surface 532. Tubing 524 may be used to transport or lift fluids produced from reservoir 530 to surface 532, and may be connected to a pumping unit, such as pumping unit 533 at surface 532, or another pump disposed downhole (not shown). For example, a submersible electric pump (SEP) may be used downhole to drive fluid flow in tubing 524.

It should be noted that while horizontal wells are depicted in FIG. 5A, and the related description refers to horizontal wells for simplicity and brevity, the same or similar tools or techniques may be used in vertical wells or directional wells as well.

It is noted that other necessary or optional components or well completion parts or tools, such as liners, packers, hangers, working strings, tubing, sensors, cables, joints, pumps, wire or cable racks, or the like, may also be provided, and installed, as are known to those skilled in the art. The sensors may include, for example, manometers, and thermometers or thermocouples, or the like. However, the exact structures and details of well 520, casing 522 including its perforations, tubing 524, any pumping unit including pumping unit 533, the other necessary and optional components, parts, or tools, and the associated equipment, are not critical to the present disclosure and have been generally described only to the extent necessary to illustrate this embodiment of the present disclosure. The nature and operation of such components, parts, tools, and equipment are known to those skilled in the art, and can be selected and implemented by those skilled in the art as suitable in a given application, in combination with the components and downhole tools expressly described in this disclosure.

As used herein, a horizontal well refers to any well that has an extended lateral wellbore section that extends generally substantially in the horizontal direction. A section of a horizontal well may extend from the surface 532 generally vertically (as illustrated in FIG. 5A), or at an inclined angle (not shown), down to a selected level into the reservoir formation. It is not necessary that the entire wellbore of a horizontal well is leveled in the horizontal direction.

As used herein, the term “surface”, in expressions such as “the surface”, “at surface”, “from surface”, or the like, should be understood to refer to the earth surface, or generally any facilities or equipment located above or on the ground near the top end of horizontal well, unless the term is otherwise qualified or the context makes it clear that the term refers to a particular surface other than the earth surface.

FIG. 5A also depicts a tool assembly 5100, which includes a cable hose 5110, a jet pump 5120, a hydraulic giant 5130, an acoustic tool unit, which includes one or more of sonotrodes 5140 and an electrohydraulic shock wave tool 5150, and flexible connectors 5160 for connecting various components or units in the tool assembly. The combination of hydraulic giant 5130, sonotrodes 5140, shock wave tool 5150, and flexible connectors 5160 may be considered as a unit collectively referred to as a downhole tool or a downhole tool unit.

It should be noted that, while various tool components are shown and discussed herein, in some embodiments it is not necessary to use all of the components described in the same tool assembly. For example, in a simple application, an ultrasonic downhole tool containing a sonotrode as described herein may be lowered into a well, which can be a vertical well, using a cable, and the tool may be powered from the surface using an ultrasonic generator. Other components of in tool assembly 5100 to be described below can be optionally selected and used.

Cable hose 5110 is used primarily to transport a chemical agent into the perforated wellbore section of well 520. However, as will be further described and will become apparent below, cable hose 5110 is also configured and adapted to provide additional functionalities, including transmission of electrical power to other downhole tools such as sonotrodes 5140 and shock wave tool 5150, and for running other downhole tools in the assembly and actuating continuous movement of such tools, so that synchronized movement of such tools with the injector of the chemical agent can be conveniently effected and controlled. Cable hose 5110 may also be used to flow other fluids downhole. For example, cable hose 5110 may be used to transport a cleaning fluid downhole to wash and clean a perforated portion of well 520, either before or after chemical treatment, as will be further described below.

Cable hose 5110 is flexible and may be formed with an armored plastic cable body. FIG. 5B depicts a transverse cross-sectional view of cable hose 5110. As illustrated in FIG. 5B, cable hose 5110 includes a plastic core 5111 defining a fluid conduit 5112. A plurality of wires, including armor wires 5113, power wires 5114, and signal wires 5115, are embedded and extend in plastic core 5111. Armor wires 5113 are used to provide mechanical strength and may be made of steel such as a suitable stainless steel.

It is noted that in different embodiments, a downhole tool or tool assembly may be lowered into a well (horizontal, vertical or directional) using a conventional string or cable used to run downhole tools into the well, as known to those skilled in the art.

Armor wires 5113 may also be made of another material with suitable mechanical properties, and do not need to be electrically conductive.

Power wires 5114 are used to transmit electrical power. Signal wires 5115 are used to transmit electric or electronic signal. Both power wires 5114 and signal wires 5115 are made of a suitable electrically conductive material, such as copper or the like. Power wires 5114 and signal wires 5115 may be made of the same material but their gauge size may be different, as a power wire may have a larger gauge size than a signal wire. The gauge size of a power wire may also vary depending on the power required to power a particular downhole tool or equipment. For example, in a particular embodiment, a suitable copper power wire may have a diameter of about 1.5 mm, and a copper signal wire may have a diameter of 0.5 mm or less. The power rating for power wires 5114 may be up to 5 kW. While two power wires and four signal wires are shown in FIG. 5B, it should be understood that the numbers of power wires 5114 and signal wires 5115 may vary in different applications, and may be selected depending on the number downhole tool units to be powered and the number of signals to be transmitted from downhole to surface. Signal wires 5115 may be used to transmit data signals from a downhole tool or equipment such as a sensor to a surface apparatus or unit, and transmit control signals from a surface apparatus or unit to a downhole tool or equipment, as needed.

The diameter of cable hose 5110 may be selected such that the diameter of fluid conduit 5112 is optimized for a given wellbore size and the downhole room available for cable hose 5110. Generally, a larger diameter for fluid conduit 5112 may be desirable to achieve a higher flow rate under the same fluid pressure. However, the size of cable hose 5110 and hence the size of fluid conduit 5112 may be limited by available space within the wellbore. In a particular embodiment, the diameter of fluid conduit 5112 may be about 15 mm. The diameter of cable hose 5110 may be selected to ensure that cable hose 5110 is of sufficient mechanical strength for performing the desired functions and have sufficient durability. In an embodiment, the outer diameter of cable hose 5110 may be 44 mm. The inner surface fluid conduit 5112 may be formed of a material chemically resistant to any chemical agent to be transported through conduit 5112. For example, if an acidic fluid is to be transported through conduit 5112, the inner surface of conduit 5112 may need to be acid-resistant. This may be achieved by selecting a suitable acid-resistant core material, or by coating an acid-resistant material on the inner wall of conduit 5112. A suitable material for the core of cable hose 5110 may be a polymer.

As can be seen in FIG. 5A, cable hose 5110 extends from surface 532, and the surface end of cable hose 5110 is connected to a source 534 of a chemical agent for supplying the chemical agent into conduit 5112 of cable hose 5110. Cable hose 5110 is also wound onto a cable drum 535 on a cable truck 536. Source 534 may be provided in any suitable manner or form, such as by way of a stationary or movable tank, or a truck carrying a fluid container. Cable hose 5110 is deployed and actuated during operation by turning cable drum 535 on truck 536. Conveniently, a geophysical truck may be adapted to carry and operate cable hose 5110. A specially designed and configured truck may also be used.

Cable hose 5110 may be otherwise deployed and actuated without truck 536, such as by using a suitable cable winding device with a motorized spindle or winding wheel (not shown). However, as can be appreciated by persons skilled in the art, using a truck carrying a cable drum can provide certain benefits and advantages. For example, the cable truck can be easily moved about either on site, or from site to site, without having to load and unload cable hose 5110 for relocation. The length of cable hose 5110 may be quite long, such as up to hundreds meters, or more than 2-3 kilometers, depending on the lengths of the wells in which cable hose 5110 is to be used. For this purpose, armored cable hose 5110 is beneficial as armor wires 5113 can provide additional stretching, bending (breaking) and torsional strength and stiffness.

Conveniently, geophysical signals from geophysical sensors (not shown) deployed downhole in well 520 may be transmitted to data analysis units (not shown) on geophysical truck 536 through one or more signal wires 5115.

While specific embodiments of cable hose 5110 are described above, it should be noted that cable hose 5110 may be modified, such as by using different materials and constructions, but still provides the same or similar functionalities as described above. For example, the cable body may be formed of a material other than a polymer plastic, as long as the material can provide sufficient physical strength and flexibility and chemical stability for the intended use. The wires may also be formed of different materials for conducting electricity.

The downhole end of cable hose 5110 extends to a downhole location near the perforated section of well 520, and passes through a junction at which a jet pump 5120 is located.

Jet pump 5120 may be any suitable conventional jet pump that has been modified as described below to allow cable hose 5110 to pass through jet pump 5120 and form a pressure seal around cable hose 5110 in jet pump 5120.

Other types of pumps may also be used. For example, in vertical wells conventional jet pumps can be used during treatment or after the treatment. When a jet pump is used, the jet pump housing may be configured to allow the downhole tool assembly 5100 to pass through it. In some cases, downhole tool assembly 5100 may be used without the use of any jet pump.

Below the junction where jet pump 5120 is located, a packer (not shown) is set to isolate the sections of well 520 above and below the packer and jet pump 5120, or in other words, to isolate tubing 524 from the section of well 520 above the packer.

Jet pump 5120 is configured to allow cable hose 5110 to pass therethrough and provide a pressure seal (not shown) around cable hose 5110 in jet pump 5120. The seal can closely and tightly engage the outside perimeter of cable hose 5110 to form a tight fluid seal, yet still allowing cable hose 5110 to slidably move back and forth during operation. The seal prevents fluid communication between tubing 524 above jet pump 5120 and the perforated wellbore section of well 520, so that a pressure differential can be established therebetween. In an embodiment, a pressure differential up to 400 atm may be created by jet pump 5120.

The downhole end of cable hose 5110 is connected and coupled to hydraulic giant 5130, which has a nozzle head (not separately shown) in fluid communication with conduit 5112 for injecting the chemical agent, or any other fluid flowing in conduit 5112, into reservoir 530 through the perforated section of well 520. In different embodiments, hydraulic giant 5130 may be replaced with another type of nozzle device for injecting fluid into the wellbore of well 520. In some embodiments, the nozzle of hydraulic giant 5130 may be oriented to inject the fluid at an about 45 degree angle to the axial direction of well 520.

In different embodiments, hydraulic giant 5130 may be modified or replaced with any suitable device for injecting the chemical agent into the wellbore. Such a device may be broadly referred to as an injector (not an injection well) for injecting the chemical agent. The injector may include a nozzle, a tubing, or another fluid device (not separately shown) that can be conveniently coupled to the downhole end of cable hose 5110 for dispersing the chemical agent in a desired manner.

One or more sonotrodes 5140 may be connected by flexible connectors 5160 to the downhole end of cable hose 5110, in series. The power input of each sonotrode 5140 is connected directly or indirectly to a power wire 5114 of cable hose 5110. To this end, a wire rack (not shown) may be provided near hydraulic giant 5130, for connecting with power wires 5114 and signal wires 5115. Lead wires (not shown) may be provided to connect input or output terminals in different downhole tools or equipment to the wire rack for respective electrical connection with power wires 5114 and signal wires 5115.

Sonic device 200 or 300 may be used as one or more of sonotrodes 5140. Waveguide 100 may also be otherwise used in one or more of sonotrodes 5140. The windings in each sonotrode 5140 may be connected to a power source for generating a varying magnetic field in its transducer.

When a sonic device, such as device 300, is used in such an embodiment, it may be beneficial to provide a pressure compensator, as illustrated in FIG. 5C.

As depicted in FIG. 5C, a compensator 320 may be provided in housing 302, which includes a wall plate 322 that is slidably and sealingly movable in the housing bore. The wall plate 322 is biased against a spring 324 mounted on an end wall 326 of housing 302. Housing 302 also has openings 328 in the section between wall plate 322 and the housing end wall 326, to provide fluid communication with the surrounding area. The strength of spring 324 is selected to provide pressure balance between the pressure in the housing bore and the fluid pressure in the surrounding area. When the surrounding pressure is reduced, spring 324 may be compressed by wall plate 322 due to a higher pressure in cooling liquid 304. When the surrounding pressure is increased, the combined force by the surrounding pressure and spring 324 pushes wall plate 322 to compress cooling liquid 304 thus increasing its pressure. Therefore, the pressures inside and outside housing 302 are balanced and compensated. The pressure load on spring 324 may be up to about 2 to about 3 atm. A minimum pressure of 2 to 3 atm may be maintained in housing 302 at all times in order to avoid cavitation inside the housing bore and prevent damage to wires or other components inside housing 302.

Conveniently, with waveguide 100, ultrasonic waves can be transmitted into the surroundings both axially and radially, and a sonotrode 5140 can be configured to optimize or maximize radial dispersion of ultrasonic waves.

Waveguides 100 and transducers described herein may be used to replace waveguides and transducers in various conventional sonotrodes or acoustic devices known to persons skilled in the art, and the persons skilled in the art will be able to design and construct sonotrodes having the above discussed features and properties. For example, waveguides and transducers described herein may be used in devices, systems or processes disclosed in U.S. Pat. No. 7,063,144 to Abramov et al., issued Jun. 20, 2006, and U.S. Pat. No. 7,059, 403 to Barrientos et al., issued Jun. 13, 2006, the entire contents of each of which are incorporated herein by reference. Other example sonotrodes and operations thereof are described in U.S. Pat. No. 7,059,413 to Abramov et al., issued Jun. 13, 2006, the entire contents of which are incorporated herein by reference. Example sonotrodes and associated surface equipment are also described in Abramova, A. et al., “Ultrasonic Technology for Enhanced Oil Recovery”, Engineering, (2014), 6, pp. 177-184, the entire contents of which are incorporated herein by reference.

Test results have shown that a push-pull type sonotrode may be beneficial in some embodiments, where longitudinal oscillation in such a sonotrode is converted to radial oscillation, and sonic waves are emitted mainly radially, when the radial and longitudinal frequencies are matched with the specified margin. Radially emitting sonic waves can increase the efficiency of the sonotrodes.

In different embodiments, the operating frequency of the sonotrodes may vary. In a selected embodiment, the operating or resonance frequency may be about 20 kHz. In some embodiments, the resonance frequency may be from about 10 to about 50 kHz, or from about 15 to about 30 kHz. The input power for each sonotrode may be in the range of about 2 to about 3 kW, up to 10 kW, or higher. A sonotrode may have an output power of about 1.5 to about 5 kW.

When selecting the sonotrodes to be used and powering the sonotrodes, it may be born in mind that in some embodiments, the threshold energy intensity for achieving acoustic effects in subterranean oil and rocks (or oil sands) may be 0.8 to 1 W/cm². Thus, the sonotrodes should be configured and arranged to achieve at least such acoustic energy intensity in a volume of the reservoir formation near the wellbore such as within a meter from the wellbore casing.

When multiple acoustic tools such as sonotrodes 5140 or shock wave tool 5150 are used in the same downhole tool unit, the acoustic tools may be connected in series with flexible connectors 5160, and by conductive wires or cables. Each sonotrode 5140 in the same assembly or unit may have a distinct resonant frequency, and the resonant frequencies of different sonotrodes 5140 may differ from each other by at least about 1 kHz. As can be appreciated, ultrasonic waves with different frequencies may penetrate into a medium to different depths.

For use in horizontal wells, multiple sonotrodes 5140 may be evenly spaced, and may extend over substantially the entire perforated section of well 520. The number of sonotrodes 5140 and how they are placed may be determined based on a number of factors including the length of the perforated wellbore section, fluid flow rate, operation efficiency, effectiveness, cost, and others.

The operation of sonotrodes 5140 may be controlled at surface, such as at a control station (not shown) located at surface. The control signal and feedback may be applied through power wires 5114 and signal wires 5115 of cable hose 5110. One or more power sources or generators (not shown) may be also be provided at surface for providing electrical power to sonotrodes 5140 through power wires 5114 of cable hose 5110.

As used herein, unless otherwise specified, a radial direction refers to a direction that is perpendicular to the axial direction of the tool in question, or to the axial direction of the wellbore in which the tool is located. Typically, the axial direction of an elongated tool is aligned generally with the axial direction of the wellbore.

The operation of each sonotrode 5140 may be controlled from surface by adjusting the power applied to the sonotrode and by actuating cable hose 5110 to move sonotrodes 5140 back and forth in the axial direction. Each sonotrode is constructed and configured to generate and direct ultrasonic waves into a volume of the reservoir near well 520 or a vertical well through the perforated wellbore portion of well 520. To this end, sonotrodes 5140 are constructed and configured to produce sufficient radial oscillation.

Tool assembly 5100 may be guided by, or hang on, another working string (not shown) previously disposed downhole.

As now can be appreciated, for use in a horizontal well such as well 520, downhole tools connected to the cable hose 5110, such as hydraulic giant 5130, sonotrodes 5140, and shock wave tool 5150 should be sized so that they can be conveniently inserted through tubing 524 and jet pump 5120. For this reason, each of the downhole tools may be sized to have a diameter similar to or smaller than the outer diameter of cable hose 5110. Since it may be desirable to provide larger tools to the extent possible under the wellbore constraints, these downhole tools may have the same outer diameter as cable hose 5110. For example, cable hose 5110, sonotrodes 5140, and shock wave tool 5150 may each have an outer diameter of about 44 mm.

While not expressly shown, it should be understood that suitable coupling, connecting or engaging devices or components will be required to connect, couple, or engage different tools and devices to each other. For example, cable couplings and seal couplings may be provided to couple cable hose 5110 to hydraulic giant 5130. At hydraulic giant 5130, cable hose 5110 may be coupled to a lug (not shown), and may be partially terminated or cut off, but power and signal wires 5114 and 5115 may extend further downhole, to provide lead lines for connecting with other downhole tools.

In some embodiments, and depending on the application, the acoustic tool unit connected to cable hose 5110 or a cable may include only one sonotrode. In other embodiments, the acoustic tool unit may include multiple sonotrodes. In some embodiments, the acoustic tool unit may include multiple sonotrodes and multiple shock wave tools.

During use, at a selected time during well completion, and prior to normal production, various necessary and optional equipment, devices and downhole tools may be lowered into the wellbore of horizontal wells 20 or vertical wells. Fixtures such as packers, a working string (not shown), a housing component or platform (not shown) for housing jet pump 5120, and tubing 524 may be installed or put in place in casing 522. Jet pump 5120 is installed into place on tubing 524.

The downhole tool unit including inter alia, sonotrodes 5140, which are connected in series as shown in FIG. 5A for horizontal wells, is connected to the downhole end of cable hose 5110 or a cable, and may be run downhole using cable hose 5110 or cable through tubing 524 in casing 522, and then through jet pump 5120. Cable hose 5110 may be lowered into well 520 by un-winding the drum 535 on cable truck 536.

As can be appreciated, while FIG. 5A depicts a horizontal well, a similar technique for installing a cable or downhole tool may be used to lower the cable or downhole tool into a horizontal well or a vertical well. Alternatively, the downhole tool may be attached to a well tubing, such as tubing 524, and lowered into the well with the well tubing.

The described sonotrodes may also be used during sonochemical treatment of vertical or horizontal wells. In this case, radiation of acoustical energy is provided during or after injection of chemicals into the treated zone. Conveniently, the simultaneous injection of chemical agent and ultrasonic energy into the perforated wellbore section and the volume of reservoir formation nearby, and the synchronized movement of the injection points, can provide synergistic effects, and improve the efficiency and effectiveness of the sonochemical treatment of the volume of reservoir formation near the perforated wellbore section and the perforated wellbore section itself.

For example, and without being limited to any particularly theory, it may be expected that certain beneficial effects, such as fluid viscosity reduction and mobility increase, induced by ultrasonic stimulation, can assist fluid movement and dispersion of the chemical agent into the volume of the reservoir formation near the perforated wellbore section. However, such beneficial effects may quickly disappear or be reduced after ultrasonic stimulation is terminated. For example, some effects may be reduced within tens of seconds or a few minutes after termination of ultrasonic stimulation. While the volume of reservoir formation is still stimulated by sufficient ultrasonic energy, the chemical agent may disperse deeper and faster into the reservoir. In addition, some chemical or physical bonds between various molecular species or materials in the reservoir formation may be temporarily broken due to the ultrasonic stimulation, which may allow the chemical agent to react with such molecular species or materials. Further, the amplitude of ultrasonic waves propagating in the reservoir formation may decay quickly and the effective region of ultrasonic stimulation tends to be limited to within a short radial distance from the perforated section of well 520. Injection of the chemical agent may result in increased permeability in the volume. Consequently, the effectiveness and treatment efficiency may be improved. The synchronized movement of the chemical and ultrasonic injection points may allow the wellbore and the reservoir formation to be more evenly and uniformly treated, and the above effects to be achieved. Tests have shown that continuous movement of the chemical and ultrasonic injection points in horizontal wells may be required to avoid clogging or blockage of the perforations in the perforated wellbore section, or may be required to achieve the above discussed beneficial effects. If the downhole tool unit were kept stationary during sonochemical treatment, it might be stuck in place after a period of operation, and it would be difficult to move it again.

During the sonochemical treatment, hydraulic (fluid) shock waves may be generated using shock wave tool 5150, in addition to ultrasonic waves to improve the treatment performance. Hydraulic shock waves generated downhole typically can penetrate further into reservoir 530, and may have a higher energy transfer efficiency. Its application may be beneficial in some cases, but may also have negative effects in other cases as are known to those skilled in the art.

The skilled person will be able to determine in a particular case whether it is desirable to apply shock waves. For example, it may be more difficult to limit the effect of shock waves to within a confined zone. If there is a nearby formation structure that should not be subjected to shock wave stimulation, it may not be suitable to apply shock waves during the treatment.

The sonochemical or ultrasonic treatment of well 520 and reservoir 530 may last any suitable period of time depending on the conditions of the particular formation, the nature of the treatment selected, and the chemical materials and sonic energy used. Depending on various factors, a sonochemical treatment may last about 30 to about 60 min per meter for a vertical well, or about 2 to 15 min per meter for a horizontal well.

The sonochemical or ultrasonic treatment of well 520 and reservoir 530 may be repeated over time when necessary or desired. For example, during normal production of oil from well 520, production may be temporarily suspended, to allow well 520 and reservoir 530 to be subjected to a further period of sonochemical or ultrasonic treatment to improve fluid flow into well 520.

The frequency, power and duration of ultrasonic waves to be generated may be selected based on a number of factors known to those skilled in the art and will not be detailed herein. It should be noted that continuous ultrasonic stimulation, for which a sonotrode described herein may be used, does not require constant generation of ultrasonic energy. Rather, the ultrasonic waves or stimulation may be generated continuously or pulsed at acceptable frequencies. As long as the effects of the ultrasonic stimulation in the reservoir formation are continuous and are not substantially reduced, the ultrasonic stimulation may be considered continuous stimulation. For example, it may be expected certain effects of ultrasonic stimulation may decay quickly within tens of seconds or minutes. The ultrasonic stimulation may be considered to be continuous, as long as such decay is not observed or has no material or observable effect on the treatment performance.

The frequency and energy intensity of the emitted ultrasonic waves may be selected dependent on various characteristics of the materials present in the reservoir and the fluids to be produced from the reservoir, such as initial viscosity, porosity, permeability, chemical or physical composition and structure, and the like. Generally, the ultrasonic waves may be emitted at a frequency of 10 to 50 kHz, such as from about 13 kHz to about 30 kHz, from about 15 kHz to about 30 kHz, or about 20 kHz. The power of the ultrasonic waves may be from 1 to about 10 kW.

Other acoustic waves generated downhole may have a frequency from about 20 Hz to about 10kHz.

Ultrasonic or sonochemical treatment of a wellbore and its proximate regions in the reservoir may last minutes, hours or days.

Depending on the length of the perforated section of well 520, or the length of the section of well 520 to be treated, and the total length of the acoustic tool unit, the acoustic tool unit and eventually the chemical injector may be moved axially along the length of well 520, so that all desired portions of well 520 and the reservoir formation nearby are subject to sonochemical or ultrasonic treatment, either at the same time or sequentially.

The ultrasonic or sonochemical treatment of a reservoir formation may be expected to improve permeability in the volume near the perforated wellbore section of a vertical or a horizontal well. As can be appreciated by those skilled in the art, permeability may sometimes decrease due to clogging and other chemical or physical effects during normal oil production. In such cases, ultrasonic or sonochemical treatment may be reapplied to improve productivity.

To achieve better or optimal results, the ultrasonic or sonochemical treatment may be designed and selected based on geophysical studies of the particular reservoir to be treated. To achieve desired synergetic effects, the selected chemical agents may need to be injected directly into the same zone that is under acoustic treatment. The treatment zone may be selected from, or limited to, zones that are expected or known to be problematic, so that the overall treatment time can be controlled and limited for improved effectiveness and efficiency.

The treatment may be controlled and adjusted based on the feedback and information obtained from downhole sensors or measurements, although the data may be processed and analysed at surface and control signals may be dispatched at surface. In this regard, signal wires 5115 and power wires 5114 in cable hose 5110 may be conveniently used.

Useful information that may be obtained from a downhole tool or sensors may include temperature, pressure, and fluid flow information.

During operation, the following properties of sonotrodes 5140 may be monitored, such as displayed at a control station at surface: power, frequency, or the like.

During treatment, information and data may be continuously processed to better control and adjust the treatment process based on the current status and expected development.

Other geophysical downhole tools (not shown) may be used during operation and treatment. For example, such tools may be related to measurement of, downhole pressure, downhole temperature, natural radiation of the rock formation in the reservoir, downhole fluid flow, magnetic location of couplings, thermoconductive flow, electrical resistance, or soil/water content.

The effectiveness of an ultrasonic or sonochemical treatment may be assessed by measuring fluid flow characteristics in the treated region immediately before and immediately after the treatment.

In some embodiments, the selection of equipment and downhole tools or materials to be used may be made to ensure that they are suitable for use and operation under the particular downhole conditions. For example, they may be selected for use under conditions at a temperature of up to 150 ° C. or higher, a maximum pressure of 60 MPa, and in an acidic environment.

During or after treatment, fluids may be produced through tubing 524, or the space between tubing 524 and casing 522, such as in a conventional manner, as can be understood by those skilled in the art.

While the particular embodiments described herein are illustrated with a horizontal well, and the described sonotrodes are particularly useful for treating a horizontal well in a reservoir containing viscous hydrocarbons, it should be understood that the sonotrodes as contemplated herein may also be applied in other wells, including inclined wells or vertical wells, and in other types of reservoirs of hydrocarbons, where fluid mobility and blockage of fluid flow near or at a perforated wellbore section may likely occur.

In different embodiments, when both production wells and injection wells are used, both types of wells may be treated as described herein.

Typically, ultrasonic and sonochemical treatment of a well may be performed during production “down-time”. Conventional down-time is often accompanied by optimization of the pumping equipment. In order to differentiate between the effects of ultrasound and normal workover we have measured the influence of ultrasonic treatment and workover on the changes in the productivity factor of the oil well and water cut i.e. the percentage of water in the recovered well fluid. Ultrasonic treatment leads to an increase of the productivity factor by 39% and decrease of the water cut of the well by 5% on average. Whereas in wells where only the optimization of pumping equipment was carried out there was a drop in the productivity factor of 5.6% and an increase in the water cut of 1.5%. The tests indicated that the success rate of the ultrasonic treatment of vertical wells reaches 90% and the increase in oil production is in the range of 40 to 100%.

Tests of sonochemical treatment were also conducted in horizontal wells. A 1 m thick formation was subjected to ultrasonic treatment after injection of a chemical reagent for 15 min. Before and after sonochemical treatment of the well, geophysical studies of the well were carried out. Based on the information received the zones for sonochemical treatment were determined. The treated area was 200 m to 300 m long, the productive formation had a porosity of 0.27, the permeability was 0.515 pm^(t) and oil saturation was 0.67.

As a result of sonochemical treatment the production of fluid and production of oil from all three treated wells grew. On average the production of fluid increased from 51 to 72 tons per day, and the production of oil from 23 to 33 tons per day. In comparison with the sonochemical treatment of vertical wells in the same region the treatment of horizontal wells improved oil production but to a lesser extent as compared to similar treatment of vertical wells, and the reduction in water use after treatment was negligible.

Chemical reagents that have been used for test treatment of horizontal wells include acids, oxidants, enzymes and chelates. Potentially all of these reagents and others may be used for sonochemical treatment of wells or reservoir formation.

Experimental results and theoretical estimations both show that the optimal treatment time of ultrasonic enhanced oil recovery (EOR) in vertical wells may be about 60 min. However, in case of sonochemical treatment for horizontal wells the optimal treatment time may be reduced. Laboratory experiments have shown that ultrasound can enhance the effect of chemicals used to improve the performance of vertical wells and to treat the wellbore perforation zone of horizontal wells.

The waveguides and transducers described herein are also useful for other applications including use in either horizontal wells or vertical wells, and in other industries.

For example, a problem in the oil extraction process is the reduced productivity due to various reasons including reduced mobility of a fluid to be produced and progressive plugging of the pores of the reservoir in the well bore region due to accumulation of solids (days, colloids, salts) that reduce the absolute permeability or interconnection of the pores. During production, fluids in the formation flow through perforations of the well into the well. The fluids entering the well may include gas, liquids and solids (particulates such as sand). The fluids may also include materials formed of heavy molecules. After a period of time, the pathways through the perforations extended within the formation may be clogged. During fluid flow, very small solid particles (known as “fines”) may tend to settle along the pathways, and can aggregate or coagulate, thus forming obstructions to fluid flow in the formation pores and reducing the production rate of fluids. As fluid flow slows down, more “fines” can settle, thus further reducing the fluid flow rate.

Dispersion of ultrasonic energy into the wellbore and the formation near the well can help to increase fluid flow or reduce the problem of clogging. For effective operation, the power of acoustic energy dispersed into the formation may be more than about 0.8 W/cm².

Thus, a further example of using embodiments of waveguides and transducers as described herein is illustrated in FIG. 6.

FIG. 6 illustrates a tool assembly 600 in a well 602 for increasing permeability in the wellbore region 612. Well 602 may be used to produce oil, gas, water, or a combination thereof. Tool assembly 600 provides acoustic stimulation in region 612, by generating not only acoustic waves propagating along the axial direction of the well, but also substantial radially propagating acoustic waves. As depicted, well 602 is a vertical well. In a different embodiment, similar arrangements may be made in a directional well or a well that is generally vertical on inclined.

As depicted in FIG. 6, well 602 includes a metal casing 610, cement wall 619 between casing 610 and wellbore region 612, an inner metal tubing 611 inside casing 610, and a packer 615 between casing 610 and tubing 611. Casing 610 near region 612 is perforated and has holes 613. Fissures 614 may be generated with a downhole tool in cement 619 and in region 612. Holes 613 and fissures 614 allow fluids to flow from region 612 of the reservoir formation into well 602.

The wellbore of well 602 may contain a liquid phase 618 formed of oil and water. In some cases, a gas phase may also be present in the wellbore. Tool assembly 600 includes an acoustic device 620 positioned in the extraction zone of the wellbore, which is connected with a cable 622. Cable 22 may be a logging cable and carries power and signal transmission wires. Acoustic device 620 may include waveguide 100, sonic device 200, sonic device 300, or modifications thereof as described herein.

In this disclosure, the terms “oil”, “hydrocarbons” or “hydrocarbon” relate to mixtures of varying compositions comprising hydrocarbons in the gaseous, liquid or solid states, which may be in combination with other fluids (liquids and gases) that are not hydrocarbons. For example, oil or hydrocarbons may include what are known as “light oil”, “heavy oil”, “extra heavy oil”, or “bitumen”. Viscous hydrocarbons refer to hydrocarbons occurring in semi-solid or solid form and having a viscosity in the range of about 1,000 to over 1,000,000 centipoise (mPa·s or cP) measured at original in-situ reservoir temperature. Depending on the in-situ density and viscosity of the hydrocarbons, the hydrocarbons may comprise, for example, a combination of light oil, heavy oil, extra heavy oil and bitumen. Heavy crude oil, for example, may be defined as any liquid petroleum hydrocarbon having an American Petroleum Institute (API) Gravity of less than about 20° and a viscosity greater than 1,000 mPa·s. Oil may be defined, for example, as hydrocarbons mobile at typical reservoir conditions. Extra heavy oil, for example, may be defined as having a viscosity of over 10,000 mPa·s and about 10° API Gravity. The API Gravity of bitumen ranges from about 12° to about 7° and the viscosity is greater than about 1,000,000 mPa·s. Native bitumen is generally non-mobile at typical native reservoir conditions.

A person skilled in the art will appreciate that in some reservoirs, either before or during oil production, fluid flow might be impeded by various factors such as low porosity, high viscosity of fluids, or the like. In some cases, at initial (or original) reservoir conditions (e.g., temperature or viscosity), before a reservoir has been treated with a chemical agent, heat, acoustic energy, or other means, the reservoir formation may have limited fluid mobility. In some cases, the fluid mobility in a reservoir may decrease after a period of oil production. In either of these cases, sonochemical or ultrasonic treatment of the formation through a well according to an embodiment of the present disclosure may conveniently increase fluid mobility in the formation.

Hydrocarbons in a reservoir of bituminous sands may be in a complex mixture comprising interactions between sand particles, fines (e.g., clay), and water (e.g., interstitial water) which may form complex emulsions during processing. The hydrocarbons derived from bituminous sands may contain other contaminant inorganic, organic or organometallic species which may be dissolved, dispersed or bound within suspended solid or liquid material. It remains challenging to separate hydrocarbons from the bituminous sands in-situ, which may impede production performance of the in-situ process. Sonochemical treatment of such a reservoir may improve production performance.

Production performance may be improved when a higher amount of oil is produced within a given period of time, or in some other manner as can be understood by those skilled in the art. For example, production performance may be improved by increasing the flow rate of fluid from the reservoir into a production well, or the flow rate of fluid from an injection well into the reservoir, or both.

Faster fluid flow in regions near a well and through perforations of the well can lead to more efficient oil production, and the increase in the flow rate can be indirectly indicated or measured by the increase in the rate of fluid production or oil production to the surface. The well may be a production well, or an injection well. In the latter case, improved fluid flow in or near the injection well may be detected by monitoring production rates at a production well in fluid communication with the injection well. Techniques for measurement of production rates have been well developed and are known to those skilled in the art.

It can now be appreciated that embodiments the waveguides, transducers and acoustic or sonic devices described herein may also be useful in other applications and fields, where more efficient radial dispersion of acoustic energy may be desirable.

For example, a device or tool described herein may be used for extraction of water from water wells. A technique described herein may be applied in water wells or for cleaning large tanks filled with fluids, where an ultrasonic device as described may be deployed into the zone to be “cleaned” and operated in the zone.

EXAMPLES

Simulation calculations were carried for embodiments of the tool as depicted in FIG. 3A. Representative simulation results for distribution of displacement during oscillation of the tool on its own frequency 18.55 kHz are shown in FIG. 7. The data was obtained using a finite element method and a software program called Eclipse.

The amplitudes of both radial and longitudinal oscillations were calculated for sonic devices constructed according to FIG. 3A with the length of the waveguide being 135 mm but with different shapes of the end portions in the waveguide resonance chamber. The relative amplitudes of radial oscillation were calculated from these results. For comparison, similar calculations were also carried out for sonic devices with similar constructions and dimensions but semi-spherical or flat end portions in the waveguide resonance chamber. The results are shown in Table II.

TABLE II Relative Amplitudes of Radial Oscillation Shape of End Portion Cone Angle (2θ) Relative Radial Amplitude Conoidal 90 2.32 Conoidal 100 2.50 Conoidal 110 2.50 Conoidal 120 2.41 Conoidal 130 2.35 Conoidal 140 2.37 Conoidal 150 2.21 Semi-Spherical 2.16 Flat 2.18

As can be seen from Table II, waveguides with conoidal end portions provide increased radial oscillation as compared to flat or semi-spherical end portions. The highest relative radial oscillation amplitudes are expected for cone angles (2θ) of from about 100 to about 110 degrees. Improved results can be expected for cone angles (2θ) at least from about 90 to about 150 degrees.

Concluding Remarks

Other features, modifications, and applications of the embodiments described here may be understood by those skilled in the art in view of the disclosure herein.

It will be understood that any range of values herein is intended to specifically include any intermediate value or sub-range within the given range, and all such intermediate values and sub-ranges are individually and specifically disclosed.

It will also be understood that the word “a” or “an” is intended to mean “one or more” or “at least one”, and any singular form is intended to include plurals herein.

It will be further understood that the term “comprise”, including any variation thereof, is intended to be open-ended and means “include, but not limited to,” unless otherwise specifically indicated to the contrary.

When a list of items is given herein with an “or” before the last item, any one of the listed items or any suitable combination of two or more of the listed items may be selected and used.

Of course, the above described embodiments of the present disclosure are intended to be illustrative only and in no way limiting. The described embodiments are susceptible to many modifications of form, arrangement of parts, details and order of operation. The invention, rather, is intended to encompass all such modification within its scope, as defined by the claims. 

What is claimed is:
 1. An acoustic waveguide comprising: a body defining a resonance chamber, the body comprising a tubular section defining a cylindrical central portion of the chamber along a longitudinal axis; and first and second end sections extending from opposite ends of the tubular section, each one of the end sections comprising an end wall tapering away from the tubular section and towards the longitudinal axis thus defining a conoidal end portion of the chamber.
 2. The waveguide of claim 1, wherein the end wall and the longitudinal axis are at an angle of about 45 to about 70 degrees.
 3. The waveguide of claim 2, wherein the angle is about 50 to about 55 degrees.
 4. The waveguide of any one of claims 1 to 3, wherein the resonance chamber contains a rarefied gas.
 5. The waveguide of any one of claims 1 to 4, wherein the resonance chamber is sized and shaped to exhibit a resonant frequency in the range of 10 to 50 kHz.
 6. The waveguide of any one of claims 1 to 5, configured and sized to optimize radial dispersion of sonic energy through the waveguide.
 7. A sonic device comprising the waveguide of any one of claims 1 to 6, and an acoustic transducer coupled to at least one of the end sections of the waveguide.
 8. The sonic device of claim 7, wherein the transducer is a magnetostrictive or piezoelectric transducer.
 9. The sonic device of claim 8, further comprising a housing, wherein the transducer is mounted in the housing and is immersed in a cooling fluid.
 10. The sonic device of claim 9, further comprising a pressure compensator in the housing.
 11. The sonic device of any one of claims 7 to 10, wherein the transducer has a working frequency, and the waveguide is configured such that a resonant frequency of the sonic device matches the working frequency.
 12. The sonic device of claim 11, wherein the resonant frequency of the sonic device is a resonant frequency of longitudinal oscillation.
 13. The sonic device of claim 11 or claim 12, wherein the resonant frequency of the sonic device differs from the working frequency of the transducer by less than 10% of the working frequency.
 14. The sonic device of any one of claims 7 to 13, wherein the transducer comprises a magnetostrictive transducer.
 15. The sonic device of claim 14, wherein the magnetostrictive transducer has first and second elongated openings, aligned and spaced apart in a longitudinal direction, and wherein a coil passes through each one of the first and second openings.
 16. The sonic device of any one of claims 7 to 15, wherein each one of the end sections of the waveguide is coupled to an acoustic transducer.
 17. A method comprising generating a radially propagating acoustic wave with the sonic device of any one of claims 7 to 16 positioned in a well penetrating a hydrocarbon reservoir.
 18. The method of claim 17, further comprising injecting a chemical agent into the well.
 19. The method of claim 17 or claim 18, wherein the sonic device is connected to an injector for injecting the chemical agent, and the sonic device and injector are moved to and fro in the well in synchronization.
 20. The method of claim 19, wherein the sonic device and injector are connected to a cable hose, the cable hose comprising a fluid conduit for supplying the chemical agent to the injector and a conducting wire for transmitting power to the sonic device.
 21. The method of claim 20, wherein the cable hose further comprises a signal wire for transmitting a signal therethrough.
 22. The method of any one of claims 17 to 21, wherein the well is a horizontal well.
 23. A downhole tool assembly comprising: the sonic device of any one of claims 7 to 16; an injector for injecting a chemical agent into a perforated wellbore portion of a well penetrating a hydrocarbon reservoir; and a movable cable hose connected to the injector and the sonic device for moving the injector and the sonic device to and fro in synchronization, the cable hose comprising a conducting wire for supplying power to the sonic device and having a conduit for supplying the chemical agent to the injector.
 24. The tool assembly of claim 23, wherein the cable hose further comprises a signal wire for transmitting a signal therethrough. 